Crosslinked synthetic polymer-based reservoir drilling fluid

ABSTRACT

A wellbore fluid includes a base fluid; and a crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer; wherein the fluid loss control agent has an extent of crosslinking that is selected so that the fluid loss control agent has a viscosity that is within a peak viscosity response of the viscosity response curve.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Patent Application No.62/270,787 filed on Jan. 7, 2016, which is incorporated herein byreference.

BACKGROUND

During the drilling of a wellbore, various fluids are used in the wellfor a variety of functions. The fluids may be circulated through a drillpipe and drill bit into the wellbore, and then may subsequently flowupward through wellbore to the surface. During this circulation, adrilling fluid may act to remove drill cuttings from the bottom of thehole to the surface, to suspend cuttings and weighting material whencirculation is interrupted, to control subsurface pressures, to maintainthe integrity of the wellbore until the well section is cased andcemented, to isolate the fluids from the formation by providingsufficient hydrostatic pressure to prevent the ingress of formationfluids into the wellbore, to cool and lubricate the drill string andbit, and/or to maximize penetration rate.

However, another wellbore fluid used in the wellbore following thedrilling operation is a completion fluid. Completion fluids broadlyrefer to any fluid pumped down a well after drilling operations havebeen completed, including fluids introduced during acidizing,perforating, fracturing, workover operations, etc. Reservoir drill-influid (RDF) is a specific type of drilling fluid that is designed todrill and complete the reservoir section of a well in an open hole,i.e., the “producing” part of the formation. Such fluids are designed tobalance the properties of the reservoir with drilling and completionprocesses. In particular, it is desirable to protect the formation fromdamage and fluid loss, and not impede future production. Many RDFscontain several solid materials including viscosifiers, drill solids,and additives used as bridging agents to prevent lost circulation.

During drilling, a filter cake may build up on the walls of a wellborein which varying sizes and types of particles accumulate. This filtercake may be removed during the initial state of production, eitherphysically, through washing action of circulating fluids, or by usingchemical treatments, e.g., acids, oxidizers, enzymes, and the like. Theamount and type of drill solids present in the filter cake may alsoaffect the effectiveness of clean up treatments, in addition to thepresence of polymeric additives that may be resistant to degradationusing chemical treatments.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed herein relate to a wellbore fluidthat includes a base fluid; and a crosslinked and branched polymericfluid loss control agent formed from at least an acrylamide monomer anda sulfonated anionic monomer; wherein the fluid loss control agent hasan extent of crosslinking that is selected so that the fluid losscontrol agent has a viscosity that is within a peak viscosity responseof the viscosity response curve.

In another aspect, embodiments disclosed herein relate to a method ofdrilling a wellbore that includes pumping a wellbore fluid into awellbore through an earthen formation, the wellbore fluid including abase fluid; and a crosslinked and branched polymeric fluid loss controlagent formed from at least an acrylamide monomer and a sulfonatedanionic monomer; wherein the fluid loss control agent has an extent ofcrosslinking that is selected so that the fluid loss control agent has aviscosity that is within a peak viscosity response of the viscosityresponse curve; operating a drilling tool in the wellbore during thepumping.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to wellbore fluidadditives for downhole applications such as mitigation of fluid loss andmaintenance of fluid viscosity. Wellbore fluids in accordance with thepresent disclosure may contain chemically crosslinked and branchedpolymeric fluid loss additives, including branched and crosslinkedcopolymers of acrylamide and a sulfonated anionic monomer. In someembodiments, wellbore fluid additives in accordance with the presentdisclosure may be used in high temperature high pressure (HTHP)applications and may impart stable viscosity and gel strength when usedin wellbore fluid formulations under extreme conditions.

During drilling, a filter cake may build up as particles and materialsof varying sizes and types from wellbore fluids are deposited andaccumulate on the walls of the borehole. Prior to production, the filtercake may be removed to some degree, either physically or chemicallyusing breaker fluids that may contain acids, oxidizers, and/or enzymes,for example. However, additives used in standard drilling fluids such asweighting solids and polymeric fluid loss materials may be resistant todegradation and conventional breaker fluids leaving residues that mayhinder efficient hydrocarbon production, particularly when drillingfluid residues are present in producing intervals.

In order to overcome possible issues of formation damage associated withstandard drilling fluids, a specialty fluid having a limited amount ofsolids and often degradable polymeric additives known as a reservoirdrill-in fluid (RDF) may be used when drilling through the reservoirsection of a wellbore. Particularly, RDFs may be formulated to minimizedamage and maximize production of exposed zones. In some respects, anRDF may resemble a completion fluid. For example, drill-in fluids may bebrines containing only selected solids of appropriate particle sizeranges (often removable salts such as calcium carbonate) and fluid lossadditives. Because completeness of removal and maximization ofproduction of hydrocarbons can be significant weighting factors, it maybe desirable in some embodiments to limit the inclusion of additivesinto the drill-in fluid to those associated with filtration control andremoval of cuttings from the wellbore.

Wellbore fluids in accordance with the present disclosure may containpolymeric fluid loss control additives that withstand HTHP conditions,yet clean up with breaker fluids and be suitable for clean drilling andreservoir drill-in applications. During standard wellbore operation,wellbore fluids are often formulated with a number of polymericadditives to tune the viscosity and gel strength of the fluid such thatwellbore fluids maintain the ability to suspend particulate additivesand drill cuttings, particularly when circulation is stopped. Anotherfunction of the drilling fluid is its ability to seal permeableformations exposed by the bit with a low permeability filter cake. Sealsare often by created by wellbore fluid additives such as polymers orbridging agents accumulating to form a filter cake on the walls of thewellbore.

However, rheological characteristics of wellbore fluids may be difficultto control because of the adverse conditions under which wellbore fluidsare used, including high temperature, high shear (caused by the pumpingand placement), high pressures, and low pH. For example, when drillingof certain deep wells, e.g., greater than 15,000 feet, or ingeothermally active formations, temperatures may be such that thermaldecomposition of certain drilling fluid additives occurs, which cancause detrimental changes in viscosity and flow characteristics thatnegatively affect the overall drilling operation.

Under HTHP conditions, polymeric materials used to viscosify wellborefluids and provide a measure of fluid loss control may degrade, causingchanges in the rheology of the fluid and may place additional strain onwellbore equipment. Exposure to HTHP conditions can have a detrimentaleffect on viscosifying agents, resulting in a loss in viscosity of thefluid at high temperatures. A breakdown of the rheology can limit oreliminate the ability of the wellbore fluid to suspend solids entrainedwithin it (such as weighting agents, bridging agents or drill cuttings)and may lead to settlement, loss in fluid density, possible blowout ofthe well, or the like.

Specialized additives for HTHP conditions often contain polymericmaterials that have exceptional resistance to extreme conditions, butcan require specialized cleanup fluids to remove. For example, manycellulose and cellulose derivatives used as viscosifiers and fluid losscontrol agents degrade at temperatures around 200° F. and higher.Hydroxyethyl cellulose, on the other hand, is considered sufficientlystable to be used in an environment of no more than about 225° F. (107°C.). Likewise, because of the high temperature, high shear, highpressures, and low pH to which well fluids are exposed, xanthan gum isconsidered stable to be used in an environment of no more than about 290to 300° F. (143 to 149° C.). However, the thermal stability of polymerssuch as xanthan gum may also contribute to decreased well productivity.As a result, expensive and often corrosive breaker fluids have beendesigned to disrupt filter cakes and residues left by these polymers,but beyond costs, the breakers may also result in incomplete removal andmay be hazardous or ineffective under HTHP conditions.

In some embodiments, wellbore fluid additives in accordance with thepresent disclosure may also exhibit enhanced cleanup properties, andallow for use as brine viscosifiers and fluid loss additives in wellboreoperations that may be sensitive to the amount of formation damagecaused by standard drilling fluid additives. To this end, wellborefluids and methods in accordance with the present disclosure may be usedto treat fluid loss in some embodiments, for example, by formulating adrilling fluid or fluid loss pill with a crosslinked fluid loss controladditive.

Wellbore fluids in accordance with the present disclosure that may beformulated as a RDF and may contain crosslinked fluid loss controladditives that aid in the removal of formation cuttings during drilling,yet may be removed using breaker fluids. Other applications for wellborefluids formulated in accordance with the present disclosure includecoiled tubing applications, completions, displacement, hydraulicfracturing, work-over, packer fluid emplacement or maintenance, welltreating, or testing operations. In some embodiments, wellbore fluids inaccordance with the present disclosure may be formulated as an RDF usedin under-reaming in highly permeable and/or poorly consolidatedformations when expanding a wellbore in a hydrocarbon-bearing formationto a wider diameter.

Crosslinked Fluid Loss Control Agent

Wellbore fluid formulations in accordance with the present disclosuremay contain crosslinked polymeric fluid loss control agents that mayinclude a copolymer formed from at least one acrylamide monomer and atleast one sulfonated anionic monomer. In other embodiments, crosslinkedand branched fluid loss control agents may also include higher ordercopolymers and block copolymers such as terpolymers, quaternarypolymers, and the like, including at least one acrylamide monomer, atleast one sulfonated anionic monomer, and optionally other monomers aswell.

In one aspect, wellbore fluids of the present disclosure incorporate acrosslinked and branched polymeric fluid loss control agent that isformed from at least an acrylamide monomer and a sulfonated anionicmonomer. In one or more embodiments, crosslinked and branched fluid losscontrol agents may include polymers and copolymers synthesized from amixture of monomers that may include acrylamide-based monomers.

Acrylamide-based monomers in accordance with the present disclosure mayplay a role in creating an effective and high temperature stable fluidloss control agents, enhancing the fluid's high temperature endurance.In addition to unsubstituted acrylamide monomers, acrylamide-basedmonomers may also include N-substituted acrylamides, such asalkylacrylamides, N-methylol, N-isopropyl, diacetone-acrylamide, N-alkylacrylamide (where alkyl is C₁ to C₁₄), N,N-dialkyl acrylamides (wherealkyl is C₁ to C₁₄), N-cycloalkane acrylamides, combinations of theabove and related compounds.

The crosslinked fluid loss control agents may also contain one or moresulfonated anionic monomers. While not limited to a particular theory,incorporation of anionic monomers may increase stability when added to acopolymer by repelling negatively charged hydroxide ions that promotehydrolysis of the acrylamide moiety of the polymer. Sulfonated anionicmonomers, such as 2-acrylamide-2-methyl-propanesulfonic acid (AMPS®), atrademark of the Lubrizol Corporation—also referred to as acrylamidetertiary butyl sulfonic acid (ATBS), vinyl sulfonate, styrene sulfonicacid, and the like, may provide tolerance to divalent cations such ascalcium and magnesium encountered in drilling fluids. Thus, theincorporation of sulfonated anionic monomers may result in an improvedthermally stable fluid loss control agent for divalent cation systems,including brine based drilling fluids. Depending upon the reactivityratio and the end use of the polymer, other sulfonated monomers may alsobe utilized for preparing an effective fluid loss control agent.

Further, it is also within the scope of the present disclosure thatother monomers can be incorporated into the crosslinked polymercomposition depending upon the end use of the polymer or the type ofaqueous base drilling fluid. For example, lipophilic monomers, such asisobornyl methacrylate, 2-ethyl hexyl acrylate, N-alkyl and N,N-dialkylacrylamide, styrene and the like can be incorporated to improve theperformance of the polymer in high brine containing drilling fluids.Also, to make it more tolerant to other electrolytes, anionic monomers,such as maleic acid, tetrahydrophthalic acid, fumaric acid, acrylic acidand the like can be incorporated into the crosslinked polymers.

In one or more embodiments, crosslinked fluid loss control agents maycontain covalent intermolecular crosslinking depending on the desiredfunctional characteristics of the polymer. In one or more embodiments,the extent of crosslinking may be selected to maximize the viscosity ofthe resulting polymer in solution. In one or more embodiments, acrosslinked fluid loss control agent may exhibit a bell-curve typeresponse for its viscosity in solution as the quantity of crosslinkerused to crosslink the co-polymer is increased. That is, the viscosityinitially increases as the quantity of crosslinker (and thus thecrosslinks) are increased until a peak viscosity is reached, at whichpoint the viscosity decreases and eventually results in a substantiallyzero slope as the quantity of crosslinker is further increased. In oneor more embodiments, the crosslinked fluid loss control agent used inthe RDF may be synthesized with an amount of crosslinker, and thusextent of crosslinking, so that its viscosity response is in the higherviscosity region of the bell-curve described above. For example, in oneor more embodiments, the extent of crosslinking in the crosslinked fluidloss control agent may be selected so that the viscosity of fluid losscontrol agent is within a peak viscosity response of the viscosityresponse curve (created by plotting viscosity as a function ofcrosslinker under otherwise constant conditions). In one or moreembodiments, the peak viscosity response may be defined as the amount ofcrosslinker that correlates to the peak amount plus or minus the amountof crosslinker that correlates to up to 75% of the area under theviscosity response curve that terminates upon reaching substantiallyzero slope. In more particular embodiments, the amount of crosslinkermay be that which correlates to within 50%, or in some embodiments 25%,of the area under the viscosity response curve.

In one or more embodiments, the peak viscosity response may be expressedas the the amount of crosslinker that correlates to the peak amount plusor minus the amount of crosslinker that correlates to 1.5 standarddeviations from the peak amount. In more particular embodiments, theamount of crosslinker correlates to the peak amount plus or minus theamount of crosslinker that correlates to 1.0 standard deviations fromthe peak amount or from 0.5 standard deviations in even more particularembodiments. Further, in one or more embodiments, the peak viscosityresponse may be expressed as the amount of crosslinker that correlatesto the peak amount plus or minus 50% of the peak amount. In moreparticular embodiments, the amount of crosslinker is the peak amountplus or minus 30% or 20% of the peak amount. Further, based on theabove, one of ordinary skill in the art would appreciate that thebreadth of the amount of crosslinker (and selection of amount ofcrosslinker) may depend, for example, on the shape of the viscosityresponse curve and the desired rheological properties for the wellborefluid and its particular application.

Crosslinking may be achieved, for example, by incorporation ofcrosslinking monomers such as methylenebisacrylamide, divinyl benzene,allylmethacrylate, tetra allyloxethane or other allylic bifunctionalmonomers. The crosslinked fluid loss control agent may have a percentageof intermolecular crosslinking that ranges from 0.25% to 10% in someembodiments, from 0.5% to 5% in other embodiments, and from 0.75% to2.5% in other embodiments.

Wellbore fluids of the present disclosure may also exhibit temperaturestability up to 250° F. (121° C.) in some embodiments, or greater that250° F. (121° C.) in other embodiments. For example, in one or moreembodiments, wellbore fluids of the present disclosure may exhibittemperature stability up to 300° F., or up to 350° F., or up to 400° F.,or up to 450° F. Temperature stability may be described herein as theability of the fluid to maintain suitable rheology at the temperatureindicated above for at least five days. In one or more embodiments, awellbore fluid of the present disclosure may exhibit low end rheology(i.e., rheology at 3 and 6 rpm) that does not deviate by more than 30percent under the elevated temperature conditions indicated above whencompared to the low end rheology at temperatures below about 250° F. Inone or more embodiments, the rheology at 3 rpm, when tested at 120° F.,for fluids according to the present disclosure may be at least 5 underany of the temperature conditions described above. In one or moreembodiments, crosslinked fluid loss control additives may be added to awellbore fluid at a concentration that that ranges from a lower limitselected from the group of 0.5, 1, 2.5, and 3 lb/bbl, to an upper limitselected from the group of 5, 10, 12, and 15 lb/bbl, where theconcentration may range from any lower limit to any upper limit. Theamount needed will vary, of course, depending upon the type of wellborefluid, contamination, and temperature conditions.

In one or more embodiments, the polymeric fluid loss control agent mayhave an average molecular weight that ranges from a lower limit selectedfrom the group of 250, 500, and 1,000 Da, to an upper limit selectedfrom the group of 100, 250, 500, and 1,000 kDa, where the molecularweight may range from any lower limit to any upper limit. As usedherein, molecular weight refers to weight average molecular weight (Mw)unless indicated otherwise.

In one or more embodiments, crosslinked fluid loss control agents may bea copolymer having a ratio of acrylamide monomer and sulfonated anionicmonomer that ranges from 0.5:1 to 10:1. In some embodiments, a ratio ofacrylamide monomer and sulfonated anionic monomer may range from 1:1 to5:1

Crosslinked Polyvinylpyrrolidone

In one or more embodiments, crosslinked polyvinylpyrrolidone may also beadded to wellbore fluids in accordance with the present disclosure toalter or maintain the rheological properties of the fluid, such as tomaintain suspension properties for solids (including weight material,bridging agents, or cuttings) or other components within the fluid. Insome embodiments, crosslinked polyvinylpyrrolidone polymers may includepolyvinylpyrrolidone homopolymers, copolymers, or block copolymerscontaining one or more polyvinylpyrrolidone domains that have beencrosslinked using various chemical reagents.

Crosslinked PVP may include crosslinking via intramolecular covalentchemical bonds, which are not adversely effected by salt or pHconditions. In one embodiment, the crosslinked polyvinylpyrrolidones maybe added to a wellbore fluid at a concentration that that ranges from alower limit selected from the group of 0.5, 1, 2.5, and 3 lb/bbl, to anupper limit selected from the group of 5, 10, 12, and 15 lb/bbl, wherethe concentration may range from any lower limit to any upper limit. Theamount needed will vary, of course, depending upon the type of wellborefluid, contamination, and temperature conditions.

The crosslinked PVP may have a percentage of intermolecular crosslinkingthat ranges from 0.25% to 10% in some embodiments, and from 0.5% to 5%in other embodiments.

When the crosslinked PVP is included, the ratio of the concentrationcrosslinked fluid loss control agent to the crosslinked PVP may bewithin a range of 1:1 to 5:1 in some embodiments, and from 1:1 to 3:1 inother embodiments.

Glycol Solvent

In one or more embodiments, crosslinked fluid loss control additivesand/or crosslinked polyvinylpyrrolidones in accordance with the presentdisclosure may be hydrated with a glycol solvent prior to addition to awellbore fluid. Hydrating the polymer additives of the presentdisclosure in a glycol solvent prior to use in a wellbore operation mayensure that the viscosity of the fluid and the fluid loss controlproperties of the fluid are stable during use, and, further, that thepolymer additives remain in an unfolded configuration in solution andresist precipitation. For example, exposing polymer additives that areincompletely hydrated to wellbore fluids that often contain high ionicstrength additives may initiate sedimentation and crashing out of thepolymer.

Glycol solvents in accordance with the present disclosure may includeoligomers of hydroxyalkylenes having 2-5 carbons and one or morehydroxyl groups. In some embodiments, glycol solvents may contain 1-5propylene or ethylene units such as ethylene glycol, diethylene glycol,propylene glycol, dipropylene glycol, tripropylene glycol, and glycolethers prepared from polyhydroxyalkylenes reacted with a to a linear orbranched alkyl group such as diethylene glycol monoethyl ether,dipropylene glycol monomethyl ether, tripropylene glycol monomethylether, ethylene glycol monobutyl ether, ethylene glycol dibutyl ether,diethylene glycol monoethyl ether, diethyleneglycol monomethyl ether,tripropylene butyl ether, dipropylene glycol butyl ether, diethyleneglycol butyl ether, butylcarbitol, dipropylene glycol methyl ether,propylene glycol n-propyl ether, propylene glycol t-butyl ether, and thelike.

Base Fluids

In one or more embodiments, crosslinked fluid loss control additivesand/or crosslinked polyvinylpyrrolidones in accordance with the presentdisclosure may be hydrated by their simple addition to a base fluid. Forexample, the crosslinked fluid loss control additives may be hydrated byfree water upon their addition to water or a brine used a base fluid. Inone or more embodiments, the fluid of the present disclosure may have anaqueous base fluid, the fluid being a monophasic fluid, in which theabove mentioned polymers are included. The aqueous medium of the presentdisclosure may be water or brine. In those embodiments of the disclosurewhere the aqueous medium is a brine, the brine is water comprising aninorganic salt or organic salt. The salt may serve to provide desireddensity to balance downhole formation pressures, and may also reduce theeffect of the water based fluid on hydratable clays and shalesencountered during drilling. In various embodiments of the drillingfluid disclosed herein, the brine may include seawater, aqueoussolutions wherein the salt concentration is less than that of sea water,or aqueous solutions wherein the salt concentration is greater than thatof sea water. Salts that may be found in seawater include, but are notlimited to, sodium, calcium, aluminum, magnesium, zinc, potassium,strontium, and lithium, salts of chlorides, bromides, carbonates,iodides, chlorates, bromates, formates, nitrates, oxides, phosphates,sulfates, silicates, and fluorides. Salts that may be incorporated in abrine include any one or more of those present in natural seawater orany other organic or inorganic dissolved salts.

In some embodiments, the fluid may be a divalent halide is selected fromthe group of alkaline earth halides or zinc halides. The brine may alsocomprise an organic salt, such as sodium, potassium, or cesium formate.Inorganic divalent salts include calcium halides, such as calciumchloride or calcium bromide. Sodium bromide, potassium bromide, orcesium bromide may also be used. The salt may be chosen forcompatibility reasons, i.e. where the reservoir drilling fluid used aparticular brine phase and the completion/clean up fluid brine phase ischosen to have the same brine phase.

Additives

In one embodiment, the drilling fluid of the disclosure may furthercontain other additives and chemicals that are known to be commonly usedin oilfield applications by those skilled in the art. A variety ofadditives can be included in the aqueous based drilling fluid of thisdisclosure with the purpose of formation of a thin, low permeabilityfilter cake which seals pores and other openings in the formations whichare penetrated by the bit. Such additives may include thinners,weighting material, gelling agents, shale inhibitors, pH buffers, etc.

Wellbore fluids of the present disclosure may contain other materialsneeded to form complete drilling fluids. Such other materials optionallymay include, for example: additives to reduce or control low temperaturerheology or to provide thinning, additives for enhancing viscosity,additives for high temperature high pressure control, and emulsionstability.

Examples of wellbore fluid thinners that may be used includelignosulfonates, lignitic materials, modified lignosulfonates,polyphosphates and tannins. In other embodiments low molecular weightpolyacrylates can also be added as thinners. Thinners are added to adrilling fluid in order to reduce flow resistance and gel development.Other functions performed by thinners include the reduction offiltration and cake thickness, to counteract the effects of salts, tominimize the effects of water on the formations drilled, to emulsify oilin water, and to stabilize mud properties at elevated temperatures.

The HTHP wellbore fluids of the present disclosure additionally includean optional weighting material, sometimes referred to as a weightingagent. The type and quantity of weighting material used may depend uponthe desired density of the final drilling fluid composition. Weightmaterials include, but are not limited to: barite, iron oxide, calciumcarbonate, magnesium carbonate, and combinations of such materials andderivatives of such materials. The weight material may be added in aquantity to result in a drilling fluid density of up to 24 pounds pergallon. In an embodiment, the particulate weighting agent may becomposed of an acid soluble material such as calcium carbonate,magnesium carbonate, Mn₃O₄, etc.

The solid weighting agents may be of any particle size (and particlesize distribution), but some embodiments may include weighting agentshaving a smaller particle size range than API grade weighing agents,which may generally be referred to as micronized weighting agents. Suchweighting agents may generally be in the micron (or smaller) range,including submicron particles in the nanosized range. One of ordinaryskill in the art would recognize that, depending on the sizingtechnique, the weighting agent may have a particle size distributionother than a monomodal distribution. That is, the weighting agent mayhave a particle size distribution that, in various embodiments, may bemonomodal, which may or may not be Gaussian, bimodal, or polymodal.

In one or more embodiments, an amine stabilizer may be used as a pHbuffer and/or thermal extender to prevent acid-catalyzed degradation ofpolymers present in the fluid. A suitable amine stabilizer may includetriethanolamine; however, one skilled in the art would appreciate thatother amine stabilizers such as methyldiethanol amine (MDEA),dimethylethanol amine (DMEA), diethanol amine (DEA), monoethanol amine(MEA), cyclic organic amines, sterically hindered amines, amides offatty acid, or other suitable tertiary, secondary, and primary aminesand ammonia could be used in the fluids of the present disclosure.

In some embodiments, the amine stabilizer may be commercially availableamine stabilizers such as PTS-200, or polyether amines polyether aminessuch as the JEFFAMINE series of polyether amines including JeffamineD-230, all of which are available from M-I L.L.C. (Houston, Tex.). Aminestabilizers may be added to a wellbore fluid in accordance with thepresent disclosure at a concentration that ranges from 0.1% to 10% byweight of the wellbore fluid in some embodiments, and from 0.5% to 5% byweight of the wellbore fluid in other embodiments. Further, is alsoenvisioned that the fluid may be buffered to a desirable pH using, forexample, magnesium oxide. The compound serves as to buffer the pH of thedrilling fluid and thus maintain the alkaline conditions under which theprocess of hydrolysis or degradation of the polymers is retarded.

The fluids may be formulated or mixed according to various procedures;however, in particular embodiments, the polymeric fluid loss controlagent of the present disclosure may be yielded in fresh water prior tobe added to a brine (or vice versa). Thus, after the polymer yields infresh water, a brine (such as a divalent halide) may be combined withthe yielded polymer. The gelling agent may be added to the yieldedpolymer either before, after, or simultaneous with the brine.

Upon mixing, the fluids of the present embodiments may be used indrilling operations. Drilling techniques are known to persons skilled inthe art and involve pumping a drilling fluid into a wellbore through anearthen formation. The fluids of the present embodiments have particularapplication for use in high temperature environments. The drilling fluidformulations disclosed herein may possess high thermal stability, havingparticular application for use in environments of up to 450° F. In yetanother embodiment, the fluids of the present disclosure are thermallystable for at least 16 hours, or for at least two days, or for at leastfive days at the elevated temperatures indicated above.

One embodiment of the present disclosure involves a method of drilling awellbore. In one such illustrative embodiment, the method involvespumping a drilling fluid into a wellbore during the drilling through areservoir section of the wellbore, and then allowing filtration of thedrilling fluid into the earthen formation to form a filter cake on thewellbore walls. The filter cake is partially removed afterwards, thusallowing initiation of the production of hydrocarbons from reservoir.The formation of such a filter cake is desired for drilling,particularly in unconsolidated formations with wellbore stabilityproblems and high permeabilities. Further, in particular embodiments,the fluids of the present disclosure may be used to drill the reservoirsection of the well, and the open hole well may be subsequentlycompleted (such as with placement of a screen, gravel packing, etc.)with the filter cake remaining in place. After the completion equipmentis installed, removal of the filter cake may be achieved through use ofa breaker fluid (or internal breaking agent).

In one or more embodiments, the fluids of the present disclosure mayalso find utility in coiled tubing applications where the hightemperature stability of the fluid could be useful. Coiled tubingapplications use a long metal pipe that can be spooled on large reels ina variety of downhole operations including well interventions,production operations, and in some instances drilling. Many of theoperations that use coiled tubing may also be done by wireline. However,coiled tubing has the advantage of being able to be pushed into thewellbore rather than the reliance on gravity with wireline and alsofluids may be pumped through the coiled tubing. In embodiments where thefluids of the present disclosure are used in coiled tubing applicationsa lubricant may be added to the wellbore fluids to reduce frictionalthough, the crosslinked fluid-loss control additive may effectivelyact as a friction reducer when used in coiled tubing applications.

Breaker Fluids

After completion of the drilling or completion process, filter cakesdeposited by drilling and treatment fluids may be broken by applicationof a breaker fluid that degrades the constituents of the filter cake.The breaker fluid may be circulated in the wellbore during or after theperformance of the at least one completion operation. In otherembodiments, the breaker fluid may be circulated either before, during,or after a completion operation has commenced to destroy the integrityof and clean up residual drilling fluids remaining inside casing orliners. The breaker fluid may contribute to the degradation and removalof the filter cake deposited on the sidewalls of the wellbore tominimize the possibility of negatively impacting production. Uponcleanup of the well, the well may then be converted to production.

The breaker fluids of the present disclosure may also be formulated tocontain an acid source to decrease the pH of the breaker fluid and aidin the degradation of filter cakes within the wellbore. Examples of acidsources that may be used as breaker fluid additives include strongmineral acids, such as hydrochloric acid or sulfuric acid, and organicacids, such as citric acid, salicylic acid, lactic acid, malic acid,acetic acid, and formic acid. Suitable organic acids that may be used asthe acid sources may include citric acid, salicylic acid, glycolic acid,malic acid, maleic acid, fumaric acid, and homo- or copolymers of lacticacid and glycolic acid as well as compounds containing hydroxy, phenoxy,carboxylic, hydroxycarboxylic or phenoxycarboxylic moieties. In one ormore embodiments, before, during, or after a completion operation hasstarted or upon conclusion of all completion operations, the circulationof an acid wash may be used to at least partially dissolve some of thefilter cake remaining on the wellbore walls.

Other embodiments may use breaker fluids that contain hydrolysableesters of organic acids and/or various oxidizers in combination with orin lieu of an acid wash. Hydrolysable esters that may hydrolyze torelease an organic (or inorganic) acid may be used, including, forexample, hydrolyzable esters of a C₁ to C₆ carboxylic acid and/or a C₂to C₃₀ mono- or poly-alcohol, including alkyl orthoesters. In one ormore embodiments, mixtures of hydrolyzable esters of dicarboxylic acidsmay be used. In one or more embodiments, the mixtures of hydrolysableesters of dicarboxylic acids may contain C₃ to C₈ dicarboxylic acids. Inone or more embodiments, the mixture of hydrolyzable esters ofdicarboxylic acids may include about 57-67 wt. % dimethyl glutarate,18-28 wt. % dimethyl succinate, and 8-22 wt. % dimethyl adipate. Inaddition to these hydrolysable carboxylic esters, hydrolysablephosphonic or sulfonic esters could be utilized, such as, for example,R¹H₂PO₃, R¹R²HPO₃, R¹R²R³PO₃, R¹HSO₃, R¹R²SO₃, R¹H₂PO₄, R¹R²HPO₄,R¹R²R³PO₄, R¹HSO₄, or R¹R²SO₄, where R¹R², and R³ are C₂ to C₃₀ alkyl-,aryl-, arylalkyl-, or alkylaryl-groups. One example of a suitablehydrolysable ester of carboxylic acid is available from M-I, L.L.C.(Houston, Tex.) under the name D-STRUCTOR.

In some instances, it may also be desirable to include an oxidant in thebreaker fluid, to further aid in breaking or degradation of polymericadditives present in a filter cake. The oxidants may be used with acoating to delay their release or they may be used without a coating.Examples of such oxidants may include any one of those oxidativebreakers known in the art to react with polymers such as polysaccharidesto reduce the viscosity of polysaccharide-thickened compositions ordisrupt filter cakes. Such compounds may include bromates, peroxides(including peroxide adducts), other compounds including a peroxy bondsuch as persulfates, perborates, percarbonates, perphosphates, andpersilicates, and other oxidizers such as hypochlorites. In one or moreembodiments, the oxidant may be included in the breaker fluid in anamount from about 1 ppb to 10 ppb. Further, use of an oxidant in abreaker fluid, in addition to affecting polymeric additives, may alsocause fragmentation of swollen clays, such as those that cause bitballing.

In some instances, it may also be desirable to include chelants in thebreaker fluid to help dissolve precipitates and other solids present inthe filtercake. Chelating agents suitable for use in the breaker fluidsof the present disclosure may include polydentate chelating agents suchas ethylenediaminetetraacetic acid (EDTA), diethylenetriaminepentaaceticacid (DTPA), nitrilotriacetic acid (NTA), ethyleneglycol-bis(2-aminoethyl)-N,N,N′,N′-tetraacetic acid (EGTA),1,2-bis(o-aminophenoxy)ethane-N,N,N′,N′-tetraaceticacid (BAPTA),cyclohexanediaminete-traacetic acid (CDTA),triethylenetetraaminehexaacetic acid (TTHA),N-(2-Hydroxyethyl)ethylenediamine-N,N′,N′-triacetic acid (HEDTA),glutamic-N,N-diacetic acid (GLDA), ethylene-diamine tetra-methylenesulfonic acid (EDTMS), diethylene-triamine penta-methylene sulfonic acid(DETPMS), amino tri-methylene sulfonic acid (ATMS), ethylene-diaminetetra-methylene phosphonic acid (EDTMP), diethylene-triaminepenta-methylene phosphonic acid (DETPMP), amino tri-methylene phosphonicacid (ATMP), and mixtures thereof. Such chelating agents may includepotassium or sodium salts thereof in some embodiments. Particularexamples of chelants that may be employed in certain embodiments includeethylenediaminetetraacetic acid (EDTA), glutamic acid diacetic acid(GLDA) (such as L-glutamic acid, N, N-diacetic acid) iminodiacetic acidsand/or salts thereof. A commercially available example of chelants thatmay be used in breaker fluid formulations is D-SOLVER EXTRA, availablefrom MI-LLC (Houston, Tex.). When included, chelants may be from about5-20% by volume of the breaker fluid.

In general, the base fluid of a breaker fluid may be may be an aqueousmedium selected from water or brine. In those embodiments of thedisclosure where the aqueous medium is a brine, the brine is watercomprising an inorganic salt or organic salt. The salt may serve toprovide desired density to balance downhole formation pressures. Invarious embodiments of the breaker fluid disclosed herein, the brine mayinclude seawater, aqueous solutions wherein the salt concentration isless than that of sea water, or aqueous solutions wherein the saltconcentration is greater than that of sea water. Salts that may be foundin seawater include, but are not limited to, sodium, calcium, aluminum,magnesium, zinc, potassium, strontium, and lithium, salts of chlorides,bromides, carbonates, iodides, chlorates, bromates, formates, nitrates,oxides, phosphates, sulfates, silicates, and fluorides. Salts that maybe incorporated in a brine include any one or more of those present innatural seawater or any other organic or inorganic dissolved salts.

In some embodiments, the base fluid for the breaker may be a divalenthalide is selected from the group of alkaline earth halides or zinchalides. The brine may also comprise an organic salt, such as sodium,potassium, or cesium formate. Inorganic divalent salts include calciumhalides, such as calcium chloride or calcium bromide. Sodium bromide,potassium bromide, or cesium bromide may also be used. The salt may bechosen for compatibility reasons, i.e. where the reservoir drillingfluid used a particular brine phase and the breaker fluid brine phase ischosen to have the same brine phase.

In one or more embodiments, a breaker fluid according to the presentdisclosure may include about 15-30% by volume of hydrolysable esters oforganic acids, 5-20% by volume of an organic acid, 5-20% by volume ofchelants, with the remaining component of the formulation being brine.

It should be appreciated that the amount of delay between the time whena breaker fluid according to the present disclosure is introduced to awell and the time when the fluids have had the desired effect ofbreaking/degrading/dispersing the filter cake may depend on severalvariables. One of skill in the art should appreciate that factors suchas the downhole temperature, concentration of the components in thebreaker fluid, pH, amount of available water, filter cake composition,etc. may all have an impact. For example downhole temperatures can varyconsiderably from 100° F. to over 400° F. depending upon the formationgeology and downhole environment. However, one of skill in the art viatrial and error testing in the lab should easily be able to determineand thus correlate downhole temperature and the time of efficacy of fora given formulation of the breaker fluids disclosed herein. With suchinformation one can predetermine the time period necessary to shut-in awell given a specific downhole temperature and a specific formulation ofthe breaker fluid.

EXAMPLES

The following examples are presented to illustrate the preparation andproperties of the fluids and should not be construed to limit the scopeof the disclosure, unless otherwise expressly indicated in the appendedclaims. All percentages, concentrations, ratios, parts, etc. are byweight unless otherwise noted or apparent from the context of their use.

Example 1—Comparison of Linear AMPS Copolymer with Crosslinked AMPS

In the following example, wellbore fluids containing a crosslinked AMPSpolymer and/or a crosslinked PVP was assayed to determine therheological properties, stability at elevated temperatures, ascontrasted with a comparative formulation C₁ containing a linear AMPScopolymer and a comparative formulation C₂ containing only a crosslinkedAMPS copolymer. The wellbore fluids were formulated as shown in Table 1,where polymer A is an AMPS polymer that has been crosslinked with 2% ofchemical crosslinker and polymer B is crosslinked with 1% of a chemicalcrosslinker. Samples were formulated in a calcium bromide brine withdefoamer, magnesium oxide, and selected sizes of SAFECARB particulatecalcium carbonate. Prior to addition to the brine base fluid, polymerswere first hydrated in a glycol solvent.

TABLE 1 Wellbore fluid formulations Sample C1 C2 3 4 14.2 CaBr₂ brine(bbls/bbl) 0.80 0.77 0.80 0.80 water (bbls/bbl) 0.07 0.07 0.07 0.07glycol solvent (bbl/bbl) 0.05 0.064 0.064 0.064 defoamer (bbls/bbl)0.001 0.001 0.001 0.001 crosslinked PVP (ppb) 6.0 — 2.0 2.0 MgO(lbs/bbl) 5.0 5.0 5.0 5.0 linear AMPS/acrylamide 2.0 — — — copolymer(lb/bbl) crosslinked — 8.0 5.0 — AMPS copolymer A (lb/bbl) crosslinked —— — 5.0 AMPS copolymer B (lb/bbl) SAFECARB 2 (lb/bbl) 34.75 35.86 34.7534.75 SAFECARB 10 (lb/bbl) 15.80 16.74 15.80 15.80 SAFECARB 20 (lb/bbl)12.64 12.88 12.64 12.64

After combining the components, the initial rheology was studied, whichwas then followed by aging portions of the fluid under varyingconditions. The thermal stability and performance of the formulations ofthis disclosure in controlling the filtrate loss from the drilling fluidwere determined by conducting the following tests.

Rheology Test

Viscosity is a measurement describing the flow properties of drillingfluids and their behavior while under influence of shear stress. Using aFann 35 Viscometer, Fann 70 Viscometer, Grace Viscometer, or othercommercially available rheometer, the rheological parameters namelyplastic viscosity (PV) and yield point (YP) are determined. One of skillin the art will appreciate that the viscosity measurements will bedependent upon the temperature of the gel composition, the type ofspindle, and the number of revolutions per minute. Generally, increasein the plastic viscosity and yield point values are proportional toincrease of the drilling fluid density, but the yield point increases bya smaller magnitude.

Plastic Viscosity Test

Plastic viscosity (PV) is one variable used in the calculation ofviscosity characteristics of a drilling fluid, measured in centipoise(cP) units. PV is the slope of the shear stress-shear rate plot abovethe yield point and is derived from the 600 rpm reading minus the 300rpm reading. A low PV indicates that the mud is capable of drillingrapidly because of the low viscosity of mud exiting at the bit. High PVis caused by a viscous base fluid and by excess colloidal solids. Tolower PV, a reduction in solids content can be achieved by dilution.

Yield Point Test

Yield point (YP) is another variable used in the calculation ofviscosity characteristics of drilling fluids, measured in pounds per 100feet square (lb/100 ft²). The physical meaning of the Yield Point (YP)is the resistance to initial flow. YP is used to evaluate the ability ofmud to lift cuttings out of the annulus. The Bingham plastic fluid plotsas a straight line on a shear-rate (x-axis) versus shear stress (y-axis)plot, in which YP is the zero-shear-rate intercept (PV is the slope ofthe line). YP is calculated from 300-rpm and 600-rpm viscometer dialreadings by subtracting PV from the 300-rpm dial reading and it isreported as lbf/100 ft². A higher YP implies that drilling fluid hasability to carry cuttings better than a fluid of similar density butlower YP.

High Temperature High Pressure Fluid Loss Test

“HTHP” is the term used for high temperature high pressure fluid loss,measured in milliliters (mL) according to API bulletin RP 13 B-2, 1990.This test is conducted for testing fluid loss behavior of mud. Mud ispressed through filter paper located in the HTHP filter press at 300° F.with differential pressure at 500 psi for 30 minutes. Thickness offilter cake stuck in filter paper should be less than 2 ml.

Gel Strength Test

The gel strength (thixotropy) is the shear stress measured at low shearrate after a mud has set quiescently for a period of time (10 secondsand 10 minutes in the standard API procedure, although measurementsafter 30 minutes or 16 hours may also be made).

Components of each formulation were combined and rheology of theresulting fluid was measured using Fann 35 rheometer at differenttemperatures before and after hot rolling the fluids at 375° F. Resultsfrom the rheological study are tabulated in Table 2.

TABLE 2 Rheology of formulation C1 Fresh Fluid Hot Rolled at 375° F. for16 Hours RPM 120° F. 40° F. 69° F. 120° F. 600 132 303 214 132 300 78172 126 83 200 58 126 94 63 100 31 77 59 40 6 6 10 8 6 3 5 6 5 5 10second gel 4 5 5 4 10 minute gel 6 6 5 5 PV 54 131 88 49 YP 24 41 38 34

Fluid loss tests were performed using 3 micron ceramic disc with 500 psidifferential pressure at 375° F. after dynamically aging the fluids byhot rolling for 16 hours. The fluid loss data is shown in the Table 3.Fluid loss results for the comparative formulation C₁ are shown in Table3.

TABLE 3 Fluid loss data for C1 Time Fluid Loss  1 minute  3.5 ml  5minutes  4.5 ml 10 minutes  5.0 ml 15 minutes  6.3 ml 30 minutes  7.0 ml 1 hour  8.7 ml  2 hours 11.5 ml  4 hours 14.0 ml

Rheology of the comparative wellbore fluid was also studied. Long termthermal stability was tested by aging the fluid at 375° F. for 3 and 7days. Rheological measurements were obtained 120° F. as in Table 4.

TABLE 4 Rheology of C1 after aging at 375° F. 3 days static 7 daysstatic Initial aging at 375° F. aging at 375° F. RPM Rheology at 120° F.600 130 126 113 300 83 81 71 200 64 63 55 100 41 40 35 6 8 6 6 3 6 4 4Top brine Separation — <10% <15%

To analyse the temperature stability of the Sample C₂ formulation, afirst sample of the fluid was hot rolled for 16 hours at 375° F., whilea second was aged statically at 375° F. for 7 days. The rheology of thesamples was measured with Fann 35 rheometer at a series of temperaturesas tabulated in Table 5.

TABLE 5 Rheology of Sample C2 Fresh 7 days Hot Rolled at Fluid . at 375°F 375° F. for 16 Hours RPM 120° F. 120° F. 40° F. 69° F. 120° F. 600 12558 318 225 136 300 85 38 215 155 95 200 67 30 173 126 76 100 46 21 12289 53 6 14 10 35 24 15 3 11 8 26 17 11 10 second 6 7 25 17 12 10 minute8 8 25 16 13 PV 40 20 103 70 41 YP 45 18 112 85 54 Top brine Separation— 18 to 26% —

After 7 days, aged samples exhibited a reduction in fluid viscosity,with a notable decrease in high end rheology (600 and 300 rpm, forexample), with respect to that at lower rpm. A drop in the yield pointof greater than 50% was also recorded. Fluid loss tests conducted at375° F. with the fluid that has been heated aged at 375° F. for sevendays. In addition, the fluid loss exhibited by the 7-day aged fluidapproximated that of the 16-hour hot-rolled fluid as shown in Table 6.

TABLE 6 Fluid loss of Sample C2 Time (min) 16 hour aging 7 day aging 0 4mL 4 mL 15 4.75 mL 6 mL 30 6 mL 7.5 mL 60 8 mL 9.5 mL

Wellbore fluid Sample C₂ exhibited some phase separation of brine fromthe remainder of the components, referred to as “top brine separation,”and a relatively low temperature yield point, which was modified by theaddition of crosslinked PVP.

Rheology of Sample 3 at 120° F. is shown in Table 7. The above fluidformulation gives less top brine separation, but low end rheology after16 hours is high. Sample 4 was also tested and the results are describedTable 8.

TABLE 7 Rheology of Sample 2 16 hour hot roll 7 days static aging RPMInitial at 375° F. at 375° F. 600 153 154 83 300 108 115 57 200 83 98 46100 61 73 35 6 14 24 18 3 11 18 12 10 seconds 14 17 — 10 minutes 18 21 —PV 45 39 26 YP 63 76 31 Top Brine separation — — <15%

TABLE 8 Rheology of Sample 3 at 120° F. 16 hours hot 7 days static Freshrolled fluid aging at RPM Fluid at 375° F. 375° F. 600 105 130 85 300 6787 61 200 51 69 50 100 33 48 37 6 7 14 14 3 6 11 11 10 seconds 7 12 1010 minutes 7 13 11 PV 38 43 24 YP 29 44 37 Top brine separation — — <15%

The fluid loss of Sample 4 after dynamically aging the fluid for 16hours was measured and the results are shown in Table 9.

TABLE 8 Fluid loss of Sample 4 Time Fluid loss volume 1 minute  3.5 ml 5minutes  4.5 ml 15 minutes  5.0 ml 30 minutes  6.5 ml 1 hour  8.5 ml 2hours 10.5 ml 4 hours 14.5 ml

Example 3—Breaker Fluid Tests

In the next example, breaker tests were performed by building 4 hoursfilter cake using the Sample 4 formulation shown in Table 1. A 14.2 ppgbreaker solution was prepared using different chemicals in a CaBr₂/ZnBr₂brine, in the presence of an added corrosion inhibitor. The filter cakewas soaked in the breaker at 375° F. for 7 days under 300 psi pressure.The breaker test results are summarized in Table 9.

TABLE 9 Results of breaker testing for filter cakes generated by theSample 4 wellbore formulation Flow back percentage in Breaker Chemistryproduction direction 15% Formic acid 40% 15% Formic acid 0 20% Formicacid 10% 5% Formic acid 0 10% Hydrogen Peroxide 0

In the second test with 15% Formic acid, there was no flow back inproduction direction, and despite disruption of the filter cake from thesurface of the filter disk, the presence of colored precipitates wasobserved and it is believed that that calcium formate was formed fromthe reaction between calcium carbonate and formic acid.

Example 4—Tests of High Temperature Stability

In the following example, a wellbore fluid containing a branched andcrosslinked AMPS acrylamide co-polymer was tested to determine itsrheological properties and their stability at elevated temperatures. Thewellbore fluid of Sample 5 was formulated as shown in Table 10. In Table10 DEFOAM-X is a defoamer used for foam control and is available fromMI-LLC (Houston, Tex.), ECF-1868 is a crosslinked AMPS acrylamideco-polymer available from M-I LLC (Houston, Tex.), SAFECARB is a calciumcarbonate available from MI-LLC (Houston, Tex.) and is added to providethe fluid with bridging solids, MgO is added to act as a pH buffer forthe fluid.

TABLE 10 Formulation of Sample 5 Additives Concentration 14.2 ppg CaBr₂brine 0.57 bbl/bbl Water 0.28 bbl/bbl DEFOAM-X 0.35 ppb ECF-1868  9.0ppb Dry CaBr₂ 55.0 ppb MgO  3.0 ppb SafeCarb 81.0 ppb

To analyse the temperature stability of the Sample 5 formulation, afirst portion of the fluid was hot rolled for 16 hours at 356° F., whilea second portion was aged statically for 16 hours at 356° F., while athird portion was aged statically at 356° F. for 7 days. The rheology ofthe samples was measured with Fann 35 rheometer at a temperature of 120°F. as tabulated in Table 11.

TABLE 11 Rheology of Sample 5 After 16 hours After 16 hours After 7Rheology Fresh hot rolled static aged days static @ 120° F. Fluid @ 356°F. @ 356° F. aged @ 356° F. 600 117 121 122 122 300 78 81 82 87 200 6265 65 73 100 40 44 43 51 6 10 11 11 10 3 7 8 8 7

The fluid of Sample 5 that was hot rolled for 16 hours was alsosubjected to HTHP Fluid Loss testing and the results are shown in table12 below.

TABLE 12 Fluid Loss of Sample 5 Time (min) New (ml) Spurt 2.5 15 4.0 305.2 60 6.5 960 (16-hr) 18.0

In the following example, a wellbore fluid containing a branched andcrosslinked AMPS acrylamide co-polymer was tested to determine itsrheological properties and its stability at elevated temperatures. Thewellbore fluid of Sample 6 was formulated as shown in Table 13. In Table13, DEFOAM-X is a defoamer used for foam control and is available fromMI-LLC (Houston, Tex.), ECF-1868 is a crosslinked AMPS acrylamideco-polymer available from MI-LLC (Houston, Tex.), SAFECARB is a calciumcarbonate available from MI-LLC (Houston, Tex.) and is added to providethe fluid with bridging solids, PTS-200 is a pH-buffer and temperaturestabilizer available from MI-LLC (Houston, Tex.), SAFE-SCAV NA is aliquid bisulfite-base additive available from MI-LLC (Houston, Tex.),SAFE-SCAV-HSW is an organic hydrogen sulfide scavenger and is availablefrom MI-LLC (Houston, Tex.), CONQOR 303A is a corrosion inhibitor thatis available from MI-LLC (Houston, Tex.), SP-101 is a sodiumpolyacrylate copolymer and is available from MI-LLC (Houston Tex.).

TABLE 13 Formulation of Sample 6 Concentration Products (Lb/bbl.) DryNaCl 40.46 Water 286.37 DEFOAM-X 0.35 ECF 1868 6.0 PTS 200 3 SAFE-SCAVNA 0.1 SAFE-SCAV HSW 2 CONQOR 303A 2 SAFECARB 2 26 SAFECARB 10 24 Barite80 SP 101 0.1

To analyse the temperature stability of the Sample 6 formulation, afirst portion of the fluid was hot rolled for 16 hours at 380° F., whilea second portion was hot rolled for 3 days at 380° F., while a thirdportion was aged statically for 3 days at 380° F., while a fourthportion was aged statically at 380° F. for 6 days. The rheology of thesamples was measured with Fann 35 rheometer at a temperature of 120° F.as tabulated in Table 14.

TABLE 14 Rheology of Sample 6 Temperature 120° F. 120° F. 120° F. 120°F. 120° F. 600 rpm 81 107 108 111 80 300 rpm 56 76 77 77 56 200 rpm 4462 63 63 47 100 rpm 30 44 45 45 33 6 rpm 8 13 14 16 13 3 rpm 7 11 11 1411 Gels 10″, 7 10 10 12 10 Lb/100 ft² Gels 10′, 7 11 10 13 11 Lb/100 ft²PV, cP 25 31 31 34 24 YP, Lb/100 ft² 31 45 46 43 32 pH 9.46 9.30 9.309.20 9.20

In the following example, a coiled-tubing fluid containing a branchedand crosslinked AMPS acrylamide co-polymer was tested to determine itsrheological properties and its stability at elevated temperatures. Thewellbore fluid of Sample 7 was formulated as shown in Table 15. In Table15, DEFOAM-X is a defoamer used for foam control and is available fromMI-LLC (Houston, Tex.), ECF-1868 is a crosslinked AMPS acrylamideco-polymer available from MI-LLC (Houston, Tex.), PTS-200 is a pH-bufferand temperature stabilizer available from MI-LLC (Houston, Tex.), DI-LOKis a fluid rheology stabilizer available from MI-LLC (Houston, Tex.).

TABLE 15 Formulation of Sample 7 Products Concentration Dry NaCl 87.5ppb Water 0.871 bbl/bbl DEFOAM-X 0.3535 ppb ECF 1868 8.0 ppb PTS 200 2.0ppb DI-LOK 5.0 ppb

To analyse the temperature stability of the Sample 7 formulation, afirst portion of the fluid was hot rolled for 16 hours at 330° F., whilea second portion was hot rolled for 48 hours at 330° F., while a thirdportion was aged statically for 16 hours at 330° F., while a fourthportion was aged statically at 330° F. for 48 hours. The rheology of thesamples was measured with Fann 35 rheometer at a temperature of 120° F.as tabulated in Table 14.

TABLE 14 Rheology of Sample 7 Hot rolled Static aged Fann-35 at 330° F.at 330° F. rheology Fresh 16 48 16 48 @ 120° F. Fluid hours Hours hourshours 600 76 87 87 77 78 300 53 61 60 52 54 200 42 49 48 42 43 100 29 3434 28 30 6 9 10 10 8 9 3 7 8 8 6 7 PV 23 26 27 25 24 YP 30 35 33 27 30pH 9.22 9.29 9.26 9.42 9.21 LSRV @ 37199 35000 36492 30394 36292 0.0636sec-1 @ 120° F. using Brookfield viscometer

The rheology of the fluid of Sample 7 that was hot rolled at 330° F. for16 hours was measured with a Fann 35 and Grace rheometer at severaltemperatures as tabulated in Table 15 below.

TABLE 15 Rheology of Sample 7 120° F 200° F 250° F 300° F 330° F Fann 35Grace Grace Grace Grace Grace 600 87 89 62 51 45 39 300 61 62 42 35 3127 200 49 49 34 28 24 26 100 34 34 23 19 17 15 6 10 10 8 6 5 7 3 8 8 6 55 7

In the following example, a wellbore fluid containing a branched andcrosslinked AMPS acrylamide co-polymer was tested to determine itsrheological properties and its stability at elevated temperatures. Thewellbore fluid of Sample 8 was formulated as shown in Table 16. In Table16, ECF-1868 is a crosslinked AMPS acrylamide co-polymer available fromMI-LLC (Houston, Tex.), PTS-200 is a pH-buffer and temperaturestabilizer available from MI-LLC (Houston, Tex.), SAFE-SCAV-HS is anorganic hydrogen sulfide scavenger and is available from MI-LLC(Houston, Tex.), CALOTHIN is a liquid anionic acrylic copolymer thatprovides rheology control and is available from MI-LLC (Houston, Tex.),and POROSEAL is a copolymer filtration control additive available fromMI-LLC (Houston, Tex.).

TABLE 16 Formulation of Sample 8 Additives Concentration Water 246.50ppb Soda Ash 0.50 ppb Sodium Chloride 61.63 ppb ECF-1868 5.0 ppb PTS-2003.0 ppb SafeScav HS 1.0 ppb Calothin 0.15 ppb Poroseal 10.50 ppb BariteUF 218.72 ppb

To analyse the temperature stability of the Sample 8 formulation, aportion of the fluid was hot rolled for 16 hours at 420° F. The rheologyof the sample was measured with Fann 35 rheometer at a temperature of120° F. as tabulated in Table 17.

TABLE 17 Rheology of Sample 8 Rheology Fresh After 16 hours hot @ 120°F. Fluid rolled at 420° F. 600 72 74 300 48 49 200 35 36 100 24 25 6 8 73 6 6

Example 5—Viscosity Difference Between Linear and Crosslinked andBranched Polymer

In this example, 2 wt. % of a co-polymer formed from an acrylamidemonomer and a sulfonated anionic monomer was dispersed in 2 wt. % CaBr₂salt solution and the viscosity was measured on a Brookfield viscometer.The results are shown in Table 18 below. In one sample the co-polymerwas a linear co-polymer, while in the other sample the co-polymer wascrosslinked and branched.

TABLE 18 Viscosity Results Polymer 1.5 rpm 6.0 rpm 30.0 rpm 60.0 rpmCrosslinked and 3700 cps 1350 cps 480 cps 320 cps Branched LinearPolymer Too low to Too low to  78 cps  74 cps measure measure

Advantageously, embodiments of the present disclosure provide wellborefluids and associated methods using such fluids that include acrosslinked polymeric fluid loss control agent. The drilling fluids ofthe present disclosure may advantageously be stable in HTHP conditionsand prevent wellbore fluid loss up to temperatures of 375° F. or even upto 450° F. in some embodiments, whereas use of conventional fluid losscontrol additives may begin to experience degradation at lowertemperatures. Additionally, use of drilling fluids containing apolymeric fluid loss control agent comprising an acrylamide and asulfonated anionic monomer and a gelling material containing a clay anda crosslinked polyvinylpyrrolidone may prevent wellbore fluid loss intothe formation by forming a filter cake on the wellbore walls uponfiltration of the drilling fluid into the earthen formation. The use oftwo gelling materials, namely a clay and a crosslinkedpolyvinylpyrrolidone, has a synergistic effect on the rheologicalproperties of the drilling fluid, depicted in superior viscosity and gelstrength properties, as well as improved fluid loss control.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this disclosure. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. § 112(f) for any limitations of any of the claimsherein, except for those in which the claim expressly uses the words‘means for’ together with an associated function.

1. A wellbore fluid, comprising: a base fluid; and a crosslinked andbranched polymeric fluid loss control agent formed from at least anacrylamide monomer and a sulfonated anionic monomer; wherein the fluidloss control agent has an extent of crosslinking that is selected sothat the fluid loss control agent has a viscosity that is within a peakviscosity response of the viscosity response curve.
 2. The wellborefluid of claim 1, wherein the acrylamide monomer is at least oneselected from unsubstituted acrylamide, alkylacrylamides, N-methylolacrylamide, N-isopropyl acrylamide, diacetone-acrylamide, N-alkylacrylamide, where alkyl is C₁ to C₁₄, N,N-dialkyl acrylamides, wherealkyl is C₁ to C₁₄, N-cycloalkane acrylamides.
 3. The wellbore fluid ofclaim 1, wherein the sulfonated anionic monomer is selected from2-acrylamide-2-methyl-propanesulfonic acid, vinyl sulfonate, and styrenesulfonic acid.
 4. The wellbore fluid of claim 1, wherein the fluid losscontrol agent contains covalent intermolecular crosslinking.
 5. Thewellbore fluid of claim 1, wherein the wellbore fluid exhibitstemperature stability up to 300° F.
 6. The wellbore fluid of claim 1,wherein the wellbore fluid exhibits low end rheology that does notdeviate by more than 30 percent under a temperature up to 300° F. whencompared to low end rheology of the fluid at temperatures below about250° F.
 7. The wellbore fluid of claim 1, wherein after aging thewellbore fluid for at least 5 days at a temperature of at least 300° F.,the rheology of the wellbore fluid at 3 rpm, when tested at 120° F., isat least
 5. 8. The wellbore fluid of claim 1, wherein the fluid losscontrol agent is present in the wellbore fluid at a concentration ofabout 0.5 to 15 lb/bbl.
 9. The wellbore fluid of claim 1, wherein thefluid loss control agent has a percentage of intermolecular crosslinkingthat ranges from 0.25 to 10%.
 10. The wellbore fluid of claim 1, whereinthe ratio of acrylamide monomer to sulfonated anionic monomer is betweenabout 0.5:1 to 10:1.
 11. The wellbore fluid of claim 1, wherein the peakviscosity response is defined as having an amount of crosslinker thatcorrelates to the peak viscosity amount plus or minus the amount ofcrosslinker that correlates to up to 75% of the area under the viscosityresponse curve. 12-20. (canceled)